The present application relates to fracturing operations that include fluid diversion cycles.
Hydrocarbon-producing wells are often stimulated by hydraulic fracturing operations. Generally, a fracturing fluid may be introduced into a wellbore penetrating a subterranean formation at a hydraulic pressure sufficient to create or extend at least one fracture in the subterranean formation. Often, proppant particles, such as graded sand, are suspended in a portion of the fracturing fluid so that the proppant particles may be placed in the resultant fractures to maintain the integrity of the fractures (after the hydraulic pressure is released) as conductive channels within the formation through which hydrocarbons can flow during production operations.
When placing the proppant particles, the fracturing fluid containing the proppant particles takes the path of least resistance and can fill the fractures unevenly. In some instances, some or all of the fracture volume does not receive sufficient proppant to maintain the integrity of the fracture. Such fractures may close completely or substantially, thereby reducing the number of conductive channels and, consequently, the hydrocarbon flow during production operations.
In an attempt to address these problems, fracturing operations often are designed to include diversion cycles where diverting agents are pumped into the fractures having proppant therein (again, due to flow through paths of least resistance). The diverting agents at least partially reduce the permeability of the fracture having proppant therein, which increases the resistance to flow therethrough. Then, as new fractures are formed, subsequently placed proppant particles may be diverted to the new fractures because the flow therethrough is less resistant to fluid flow than the propped fractures with diverting agent therein.
Typically, the amount of diverting agent placed downhole during each of the diversion cycles is based on the past experience of operators. In some instances, pressure diagnostics may be performed at the beginning of or during the fracturing operation to ascertain the amount of fractures that need to be propped and diverted. In these pressure diagnostics, the wellbore pressure is measured at a series of reduced injection rates of the fracturing fluid and a zero injection rate of the fracturing fluid. Then, the change in wellbore pressure over all of the reduced and zero injection rates is used to estimate the extent of the fractures using known algorithms, which in turn, provides an estimation of the number of propping and diversion parameters for the fracturing operation (e.g., the number of corresponding cycles and amount of proppant particles and diverting agent to use).
Reducing the injection rate to zero in these methods is often undesirable because stopping fluid flow may cause already formed proppant packs to change. Additionally, using a zero injection rate adds time and cost to the fracturing operation. In some instances, over the course of a series of treatment for a single well, a half-day or more may be added to the fracturing operation when performing these pressure diagnostics.